Methods for Controlling Formation Fines Migration

ABSTRACT

Generally, a consolidating treatment fluid includes at least an aqueous base fluid and an ultra-dilute water-based curable resin. The consolidating treatment fluid may be used in a plurality of subterranean operations to consolidate the unconsolidated particles within the subterranean formation.

BACKGROUND

The present invention relates to methods for controlling formation fines migration.

Hydrocarbon wells are often at least partially located in unconsolidated portions of a subterranean formation. As used herein, the term “unconsolidated portion of a subterranean formation” is used to mean a portion of a subterranean formation that comprises loose particulate matter (e.g., particulates of sandstones, carbonates, limestones, coal beds, shales, diatomites, and chalks) that can migrate out of the formation with, among other things, the oil, gas, water, and/or other fluids recovered out of the well. The particulate material in a relatively unconsolidated portion of a subterranean formation may be readily entrained by recovered fluids, for example, those wherein the particulates in that portion of the subterranean formation are bonded together with insufficient bond strength to withstand the forces produced by the production of fluids through those regions of the formation. The presence of particulate matter, such as sand, in the recovered fluids is disadvantageous and undesirable in that the particulates may abrade pumping and other producing equipment and reduce the fluid production capabilities of certain portions of a subterranean formation.

One method used to control loose sands in unconsolidated portions of subterranean formations involves consolidating the particulates in the area of interest into hard, permeable masses. This is usually accomplished by treating the unconsolidated portion of the formation with treatment fluids comprising consolidating agents like resins. Generally, the concentration of the resins in the treatment fluids is relatively high, which leads to accumulation of the resins near the wellbore.

However, resin accumulation may hinder the penetration of additional resin into the subterranean formation, thereby yielding essentially a near-wellbore treatment that leaves formation fines further from the wellbore untreated. Additionally, resin accumulation may lead to plugging of pores and interstitial space between formation fines once consolidated, which ultimately reduces the permeability of the subterranean formation.

When consolidating treatments adversely affect the permeability of zones in a subterranean formation, remedial clean-up operations may be necessary. Often clean-up operations involve chemicals that are less environmentally friendly and more expensive than the original consolidating agents used. Additionally, the increased rig-time before production of hydrocarbons can begin can be very costly. Therefore, methods that enable deeper penetration so as to consolidate more formation fines while minimally impacting the permeability of the formation would be of use to one skilled in the art.

SUMMARY OF THE INVENTION

The present invention relates to methods for controlling formation fines migration.

Some embodiments of the present invention involve introducing a consolidating treatment fluid into at least a portion of a subterranean formation comprising unconsolidated formation fines; and allowing the resin to cure so as to consolidate the unconsolidated formation fines. Generally, the consolidating treatment fluid includes at least an aqueous base fluid and a water-based curable resin at about 0.01% to about 3% by weight of the aqueous base fluid.

Other embodiments of the present invention involve introducing a preflush treatment fluid into at least a portion of a subterranean formation comprising unconsolidated formation fines, the preflush treatment fluid comprising a first aqueous base fluid; introducing a consolidating treatment fluid in the portion of the subterranean formation; and allowing the resin to cure so as to consolidate the unconsolidated formation fines; and producing hydrocarbon fluids from the portion of the subterranean formation. Generally, the treatment fluid includes at least an aqueous base fluid, a two-component epoxy-based resin at about 0.01% to about 3% by weight of the aqueous base fluid, an amine-based curing agent at about 0.01% to about 3% by weight of the aqueous base fluid, and a silane coupling agent at about 0.01% to about 2% by weight of the aqueous base fluid.

Still other embodiments of the present invention involve introducing a consolidating treatment fluid in the portion of the subterranean formation; allowing the resin to cure so as to consolidate the unconsolidated formation fines; and producing hydrocarbon fluids from the portion of the subterranean formation. Generally, the treatment fluid includes at least an aqueous base fluid, a two-component epoxy-based resin at about 0.01% to about 3% by weight of the aqueous base fluid, an amine-based curing agent at about 0.01% to about 3% by weight of the aqueous base fluid, and a silane coupling agent at about 0.01% to about 2% by weight of the aqueous base fluid.

The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of the present invention, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to those skilled in the art and having the benefit of this disclosure.

FIG. 1 illustrates the test cell used for analyzing consolidation fluid methods.

FIG. 2 provides an image of consolidated Brazos River sand fines after application of an ultra-dilute, water-soluble curable resin.

FIG. 3 provides an image of consolidated Brazos River sand fines after application of an ultra-dilute, water-soluble curable resin.

DETAILED DESCRIPTION

The present invention relates to methods for controlling formation fines migration.

The methods of the present invention may, in some embodiments, provide for the consolidation of formation fines with water-based, ultra-dilute curable resins that may penetrate greater distances from the wellbore. Further, the use of ultra-dilute curable resins may provide for less accumulation of the resin, so as to minimize any deleterious effects on permeability of the subterranean formation. Additionally, the curable nature of the resins for use in conjunction with the present invention may advantageously provide better cohesion between formation fines and adjacent surfaces like other formation fines or faces of the subterranean formation.

As a consequence of using curable resins in an ultra-dilute concentration, the absolute amount of curable resin introduced in the subterranean formation may be less than is traditionally used, which may provide cost savings and minimize environmental impact.

The methods of the present invention, may in some embodiments, be advantageously employed in formations having unconsolidated formation fines. For example, subterranean formations that may be particularly susceptible to the formation of particulates include, but are not limited to, sandstones, carbonates, limestones, coal beds, shales, diatomites, and chalks.

It should be noted that when “about” is provided at the beginning of a numerical list, “about” modifies each number of the numerical list. It should be noted that in some numerical listings of ranges, some lower limits listed may be greater than some upper limits listed. One skilled in the art will recognize that the selected subset will require the selection of an upper limit in excess of the selected lower limit.

Some embodiments of the present invention may involve consolidating formation fines with a water-based curable resin. Some embodiments of the present invention may involve introducing a consolidating treatment fluid into a wellbore penetrating a subterranean formation. In some embodiments, a consolidating treatment fluid for use in conjunction with the present invention may comprise an aqueous base fluid and a water-based curable resin. In some embodiments, the water-based curable resin may be present in a consolidating treatment fluid at a concentration ranging from a lower limit of about 0.01%, 0.05%, or 0.1% by weight of the aqueous base fluid to an upper limit of about 3%, 1%, or 0.5% by weight of the aqueous base fluid, wherein the concentration of the water-based curable resin may range from any lower limit to any upper limit and encompass any range therebetween.

The term “resin” as used herein refers to any of numerous physically similar polymerized synthetics or chemically modified natural resins including thermoplastic materials and thermosetting materials. Resins that may be suitable for use in the present invention may include substantially all water-based resins known and used in the art. Suitable water-based curable resins for use in conjunction with the present invention may include, but are not limited to, epoxy-based resins, novolak resins, polyepoxide resins, phenol-aldehyde resins, urea-aldehyde resins, urethane resins, phenolic resins, furan resins, furan/furfuryl alcohol resins, phenolic/latex resins, phenol formaldehyde resins, polyester resins and hybrids and copolymers thereof, polyurethane resins and hybrids and copolymers thereof, acrylate resins, or any combination thereof. Specific examples of such resins are discussed below. By way of nonlimiting example a consolidating treatment fluid may comprise about 0.01% to about 3% w/w epoxy-based resin, about 0.01% to about 3% w/w amine-based curing agent, about 0.01% to about 2% w/w silane coupling agent, and about 92% to about 99% aqueous base fluid.

Aqueous base fluids suitable for use in conjunction with the present invention may comprise fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water or produced water), seawater, produced water (e.g., water produced from a subterranean formation), aqueous-miscible fluids, or combinations thereof. Generally, the water may be from any source, provided that it does not contain components that might adversely affect the stability and/or performance of the first treatment fluids or second treatment fluids of the present invention. In certain embodiments, the density of the aqueous base fluid can be adjusted, among other purposes, to provide additional particulate transport and suspension in the treatment fluids used in the methods of the present invention. In certain embodiments, the pH of the aqueous base fluid may be adjusted (e.g., by a buffer or other pH adjusting agent), among other purposes, to activate a crosslinking agent and/or to reduce the viscosity of the first treatment fluid (e.g., activate a breaker, deactivate a crosslinking agent). In these embodiments, the pH may be adjusted to a specific level, which may depend on, among other factors, the types of gelling agents, acids, and other additives included in the treatment fluid. One of ordinary skill in the art, with the benefit of this disclosure, will recognize when such density and/or pH adjustments are appropriate.

Suitable aqueous-miscible fluids may include, but not be limited to, alcohols, e.g., methanol, ethanol, n-propanol, isopropanol, n-butanol, sec-butanol, isobutanol, and t-butanol; glycerins; glycols, e.g., polyglycols, propylene glycol, and ethylene glycol; polyglycol amines; polyols; any derivative thereof; any in combination with salts, e.g., sodium chloride, calcium chloride, calcium bromide, zinc bromide, potassium carbonate, sodium formate, potassium formate, cesium formate, sodium acetate, potassium acetate, calcium acetate, ammonium acetate, ammonium chloride, ammonium bromide, sodium nitrate, potassium nitrate, ammonium nitrate, ammonium sulfate, calcium nitrate, sodium carbonate, and potassium carbonate; any in combination with an aqueous-based fluid, and any combination thereof.

In some embodiments, the aqueous base fluid may be foamed. In some embodiments a consolidating treatment fluid for use in conjunction with the present invention may comprise an aqueous base fluid, a water-based curable resin, a gas, and a foaming agent.

In some embodiments, the gas is selected from the group consisting of nitrogen, carbon dioxide, air, methane, helium, argon, and any combination thereof. One skilled in the art, with the benefit of this disclosure, should understand the benefit of each gas. By way of nonlimiting example, carbon dioxide foams may have deeper well capability than nitrogen foams because carbon dioxide emulsions have greater density than nitrogen gas foams so that the surface pumping pressure required to reach a corresponding depth is lower with carbon dioxide than with nitrogen.

In some embodiments, the quality of the foamed treatment fluid may range from a lower limit of about 5%, 10%, 25%, 40%, 50%, 60%, or 70% gas volume to an upper limit of about 95%, 90%, 80%, 75%, 60%, or 50% gas volume, and wherein the quality of the foamed treatment fluid may range from any lower limit to any upper limit and encompass any subset therebetween. Most preferably, the foamed treatment fluid may have a foam quality from about 85% to about 95%, or about 90% to about 95%.

Suitable foaming agents for use in conjunction with the present invention may include, but are not limited to, cationic foaming agents, anionic foaming agents, amphoteric foaming agents, nonionic foaming agents, or any combination thereof. Nonlimiting examples of suitable foaming agents may include, but are not limited to, surfactants like betaines, sulfated or sulfonated alkoxylates, alkyl quaternary amines, alkoxylated linear alcohols, alkyl sulfonates, alkyl aryl sulfonates, C10-C20 alkyldiphenyl ether sulfonates, polyethylene glycols, ethers of alkylated phenol, sodium dodecylsulfate, alpha olefin sulfonates such as sodium dodecane sulfonate, trimethyl hexadecyl ammonium bromide, and the like, any derivative thereof, or any combination thereof. Foaming agents may be included in foamed treatment fluids at concentrations ranging typically from about 0.05% to about 2% of the liquid component by weight (e.g., from about 0.5 to about 20 gallons per 1000 gallons of liquid).

In some embodiments, a consolidating treatment fluid for use in conjunction with the present invention may further comprise additives. Suitable additives for use in conjunction with the present invention may include, but are not limited to, salts, weighting agents, inert solids, fluid loss control agents, emulsifiers, dispersion aids, corrosion inhibitors, emulsion thinners, emulsion thickeners, viscosifying agents, gelling agents, surfactants, particulates, proppants, gravel particulates, lost circulation materials, pH control additives, breakers, biocides, crosslinkers, stabilizers, chelating agents, scale inhibitors, gas hydrate inhibitors, mutual solvents, oxidizers, reducers, friction reducers, clay stabilizing agents, or any combination thereof. One skilled in the art with the benefit of this disclosure should understand the appropriate additives and concentrations thereof for use in conjunction with the present invention to achieve the desired result and so as to maintain operability of the methods of the present invention.

By way of nonlimiting example, the consolidating treatment fluid for use in conjunction with the present invention may comprise an aqueous base fluid, a water-based curable resin, and clay stabilizing agents. Suitable clay stabilizing agents for use in conjunction with the present invention may include, but are not limited to, salts, polymers, resins, soluble organic stabilizing compounds, or any combination thereof. Examples of suitable clay stabilizing components and mechanisms of stabilization may be found in U.S. Pat. No. 7,740,071 entitled “Clay Control Additive for Wellbore Fluids” filed on Jun. 23, 3006, U.S. Pat. No. 5,197,544 entitled “Method for Clay Stabilization with Quaternary Amines” filed on Dec. 18, 1991, U.S. Pat. No. 4,366,073 entitled “Oil Well Treating Method and Composition” filed on Feb. 4, 1980, and U.S. Patent Application Publication Number 2004/0235677 entitled “Methods and Compositions for Stabilizing Swelling Clays or Migrating Fines in Formations” filed on May 23, 2003, each of which is incorporated herein by reference. Stabilizing components may interact with the surfaces, interlayers, and core of clays and clay platelets to mitigate or reverse clay hydration and swelling.

Some embodiments of the present invention may involve introducing a consolidating treatment fluid into at least a portion of the subterranean formation comprising unconsolidated formation fines and allowing the resin to cure so as to consolidate the unconsolidated formation fines. Some embodiments may further involve introducing a preflush treatment fluid prior to introduction of the consolidation treatment fluid. In some embodiments, a preflush treatment fluid may comprise an aqueous base fluid. Suitable aqueous base fluids may include, but are not limited to, those described herein. In some embodiments, the aqueous base fluids of the preflush treatment fluid and of the consolidating treatment fluid may be the same or different.

In some embodiments the preflush treatment fluid and/or the consolidating treatment fluid may be introduced into the subterranean formation at matrix flow rate.

Some embodiments of the present invention may involve producing hydrocarbon fluids from the portion of the subterranean formation comprising the portion of the subterranean formation comprising formation fines consolidated with methods using water-based curable resins as described herein.

Some embodiments of the present invention may involve treating the portion of the subterranean formation comprising formation particles consolidated with methods using water-based curable resins as described herein. Suitable treatment operations may include, but are not limited to, lost circulation operations, stimulation operations, sand control operations, completion operations, acidizing operations, scale inhibiting operations, water-blocking operations, clay stabilizer operations, fracturing operations, frac-packing operations, gravel packing operations, wellbore strengthening operations, and sag control operations. The methods and compositions of the present invention may be used in full-scale operations or pills. As used herein, a “pill” is a type of relatively small volume of specially prepared treatment fluid placed or circulated in the wellbore.

As stated above, the methods of the present invention may be employed in any subterranean treatment where unconsolidated particulates reside in the formation. These unconsolidated particulates may comprise, among other things, sand, gravel, fines, and/or proppant particulates within the open space of one or more fractures in the subterranean formation (e.g., unconsolidated particulates that form a proppant pack or gravel pack within the formation). Using the consolidation fluids and methods of the present invention, the unconsolidated particulates within the formation may be remedially treated to consolidate the particulates into a cohesive, consolidated, yet permeable pack and minimize or reduce their production with production fluids. For example, in some embodiments, the consolidation fluid, preflush fluid, and/or post-flush fluid may be applied to remedially treat a gravel pack or frac-packs that has failed due to screen damage (often caused by screen erosion) to reduce the production of gravel, proppant, or formation sand with the production fluid.

By way of nonlimiting example, some embodiments may involve fracturing operations that include water-based curable resins as described herein. For example, some embodiments may involve using a consolidating treatment fluid as a pad and/or pre-pad fluid by introducing the consolidating treatment fluid into a subterranean formation at a pressure sufficient to create or extend at least one fracture, where the consolidating treatment fluid comprises an aqueous base fluid and a water-based curable resin, and then introducing a plurality of proppant particles into the formation so as to create a proppant pack in the at least one fracture. In some embodiments, the water curable resin may be allowed to cure before, during, and/or after introduction of the proppant particles.

By way of another nonlimiting example, some embodiments of the present invention may involve remedial operations using consolidating treatment fluids to treat portions of the subterranean formation in close proximity to proppant packs and/or gravel packs. For example, some embodiments of the present invention may involve introducing a consolidating treatment fluid comprising an aqueous base fluid and a water-based curable resin into at least a portion of the subterranean formation in close proximity to a proppant pack and/or a gravel pack and then allowing the water-based curable resin to cure so as to consolidate unconsolidated particles, e.g., formation fines, in close proximity to the proppant pack and/or gravel pack. Such an operation may advantageously reduce and/or mitigate plugging of a proppant pack and/or gravel pack by unconsolidated particles, and consequently mitigating decreases in hydrocarbon production.

By way of yet another nonlimiting example, some embodiments of the present invention may involve gravel packing operations that include water-based curable resins as described herein. For example, some embodiments of the present invention may involve introducing a consolidating treatment fluid comprising an aqueous base fluid, a water-based curable resin, and a plurality of gravel particulates into a wellbore so as to place the gravel particulates in an annulus between a screen and the wellbore, and then allowing the water-based curable resin to cure thereby yielding consolidated particles of and/or in close proximity to the gravel pack, e.g., a consolidated gravel pack and/or consolidated formation fines in close proximity to the gravel pack.

By way of another nonlimiting example, some embodiments of the present invention may involve using a water-based curable resin as described herein in an injection well operation. Generally, injection wells are used in conjunction with production wells so as to maintain reservoir pressure and consequently production levels through the production well. To maintain reservoir pressure, injection wells typically push fluid or gases through the subterranean formation toward the production well. In formations comprising unconsolidated formation fines, the fluid or gas from the injection well may carry the unconsolidated formation fines, which may lead to (1) formation plugging and inefficiency in pushing the injection fluid or gas through the subterranean formation and/or (2) the eventual production of formation fines. Similarly, when proppant packs are reached, the fluid or gas from the injection well disrupt the proppant pack, plug the proppant pack with carried formation fines, and/or eventually cause proppant particles to reach the wellbore of the production well. Accordingly, some embodiments of the present invention may involve injecting a consolidating treatment fluid comprising an aqueous base fluid and a water curable resin into a subterranean formation through an injection well so as to consolidate particles as the consolidating treatment fluid moves through the subterranean formation from the injection well towards a production well.

In some embodiments, the resin may be emulsified prior to being suspended or dispersed in the aqueous base fluid. Furthermore, in some embodiments the resin may be present in the consolidation fluid without the use of a solvent to alter the viscosity of the resin. Due to the absence of such a solvent, in particular embodiments the fluids may exhibit higher flash points and pose fewer environmental, safety, and/or compatibility concerns than consolidation fluids comprising a solvent.

Emulsified resins suitable for use in conjunction with the present invention may include all resins known in the art that are capable of forming a hardened, consolidated mass. The resins may enhance the grain-to-grain contact between the individual particulates within the formation, helping bring about the consolidation of the particulates into a cohesive and permeable mass. Many such resins are commonly used in subterranean consolidation operations, and some suitable resins may include, but are not limited to, two-component epoxy-based resins, novolak resins, polyepoxide resins, phenol-aldehyde resins, urea-aldehyde resins, urethane resins, phenolic resins, furan resins, furan/furfuryl alcohol resins, phenolic/latex resins, phenol formaldehyde resins, polyester resins and hybrids and copolymers thereof, polyurethane resins and hybrids and copolymers thereof, acrylate resins, or any combination thereof. Some suitable resins, such as epoxy resins, may be cured with an internal catalyst or activator so that when pumped down hole, they may be cured using only time and temperature. Other suitable resins, such as furan resins generally require a time-delayed catalyst or an external catalyst to help activate the polymerization of the resins if the cure temperature is low (i.e., less than 250° F.), but will cure under the effect of time and temperature if the formation temperature is above about 250° F., preferably above about 300° F. It is within the ability of one skilled in the art, with the benefit of this disclosure, to select a suitable resin for use in embodiments of the present invention and to determine whether a catalyst is required to trigger curing.

Selection of a suitable resin may be affected by the temperature of the subterranean formation to which the fluid will be introduced. By way of example, for subterranean formations having a bottom hole static temperature (“BHST”) ranging from about 60° F. to about 250° F., two-component epoxy-based resins comprising a hardenable resin component and a hardening agent component containing specific hardening agents may be preferred. For subterranean formations having a BHST ranging from about 300° F. to about 600° F., a furan-based resin may be preferred. For subterranean formations having a BHST ranging from about 200° F. to about 400° F., either a phenolic-based resin or a one-component HT epoxy-based resin may be suitable. For subterranean formations having a BHST of at least about 175° F., a phenol/phenol formaldehyde/furfuryl alcohol resin may also be suitable.

In some embodiments, emulsified resins may be emulsified prior to being suspended or dispersed in the aqueous base fluid. By using a resin emulsified prior to being suspended or dispersed in the aqueous base fluid, particular embodiments of the present invention may offer the advantage of easier handling and require less preparation in the field. Examples of suitable emulsifying agents may include surfactants, proteins, hydrolyzed proteins, lipids, glycolipids, and nano-sized particulates, such as fumed silica.

One type of resin suitable for use in the methods of the present invention is a two-component epoxy-based resin comprising a liquid hardenable resin component and a liquid hardening agent component. The liquid hardenable resin component comprises a hardenable resin and an optional solvent. The solvent may be added to the resin to reduce its viscosity for ease of handling, mixing and transferring. It is within the ability of one skilled in the art, with the benefit of this disclosure, to determine if and how much solvent may be needed to achieve a viscosity suitable to the subterranean conditions. Factors that may affect this decision include geographic location of the well, the surrounding weather conditions, and the desired long-term stability of the consolidating agent. An alternate way to reduce the viscosity of the hardenable resin is to heat it. The second component is the liquid hardening agent component, which comprises a hardening agent, an optional silane coupling agent, a surfactant, an optional hydrolyzable ester for, among other things, breaking gelled fracturing fluid films on proppant particulates, and an optional liquid carrier fluid for, among other things, reducing the viscosity of the hardening agent component.

Examples of hardenable resins that can be used in the liquid hardenable resin component include, but are not limited to, organic resins such as bisphenol A diglycidyl ether resins, butoxymethyl butyl glycidyl ether resins, bisphenol A-epichlorohydrin resins, bisphenol F resins, polyepoxide resins, novolak resins, polyester resins, phenol-aldehyde resins, urea-aldehyde resins, furan resins, urethane resins, glycidyl ether resins, other epoxide resins, and combinations thereof. In some embodiments, the hardenable resin may comprise a urethane resin. Examples of suitable urethane resins may comprise a polyisocyanate component and a polyhydroxy component. Examples of suitable hardenable resins, including urethane resins, that may be suitable for use in the methods of the present invention include those described in U.S. Pat. No. 6,582,819 entitled “Low Density Composite Proppant, Filtration Media, Gravel Packing Media, and Sports Field Media, and Methods of Making and Using Same” filed on Feb. 1, 2001; U.S. Pat. No. 4,585,064 entitled “High Strength Particulates” filed on Jul. 2, 1984; U.S. Pat. No. 6,677,426 entitled “Modified Epoxy Resin Composition, Production Process for the Same and Solvent-Free Coating Comprising the Same” filed on May 14, 2002; and U.S. Pat. No. 7,153,575 entitled “Particulate Material having Multiple Curable Coatings and Methods of Making and Using Same” filed on May 28, 2003, the entire disclosures of which are herein incorporated by reference.

The hardenable resin may be included in the liquid hardenable resin component in an amount in the range of about 5% to about 100% by weight of the liquid hardenable resin component. It is within the ability of one skilled in the art, with the benefit of this disclosure, to determine how much of the liquid hardenable resin component may be needed to achieve the desired results. Factors that may affect this decision include which type of liquid hardenable resin component and liquid hardening agent component are used.

Any solvent that is compatible with the hardenable resin and achieves the desired viscosity effect may be suitable for use in the liquid hardenable resin component. Suitable solvents may include butyl lactate, dipropylene glycol methyl ether, dipropylene glycol dimethyl ether, dimethyl formamide, diethyleneglycol methyl ether, ethyleneglycol butyl ether, diethyleneglycol butyl ether, propylene carbonate, methanol, butyl alcohol, d′ limonene, fatty acid methyl esters, and butylglycidyl ether, and combinations thereof. Other preferred solvents may include aqueous dissolvable solvents such as, methanol, isopropanol, butanol, and glycol ether solvents, and combinations thereof. Suitable glycol ether solvents include, but are not limited to, diethylene glycol methyl ether, dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a C2 to C6 dihydric alkanol containing at least one C1 to C6 alkyl group, mono ethers of dihydric alkanols, methoxypropanol, butoxyethanol, and hexoxyethanol, and isomers thereof. Selection of an appropriate solvent is dependent on the resin composition chosen and is within the ability of one skilled in the art, with the benefit of this disclosure.

As described above, use of a solvent in the liquid hardenable resin component is optional but may be desirable to reduce the viscosity of the hardenable resin component for ease of handling, mixing, and transferring. However, as previously stated, it may be desirable in some embodiments to not use such a solvent for environmental or safety reasons. It is within the ability of one skilled in the art, with the benefit of this disclosure, to determine if and how much solvent is needed to achieve a suitable viscosity. In some embodiments, the amount of the solvent used in the liquid hardenable resin component may be in the range of about 0.1% to about 30% by weight of the liquid hardenable resin component. Optionally, the liquid hardenable resin component may be heated to reduce its viscosity, in place of, or in addition to, using a solvent.

Examples of the hardening agents that can be used in the liquid hardening agent component include, but are not limited to, cyclo-aliphatic amines, such as piperazine, derivatives of piperazine (e.g., aminoethylpiperazine) and modified piperazines; aromatic amines, such as methylene dianiline, derivatives of methylene dianiline and hydrogenated forms, and 4,4′-diaminodiphenyl sulfone; aliphatic amines, such as ethylene diamine, diethylene triamine, triethylene tetraamine, and tetraethylene pentaamine; imidazole; pyrazole; pyrazine; pyrimidine; pyridazine; 1H-indazole; purine; phthalazine; naphthyridine; quinoxaline; quinazoline; phenazine; imidazolidine; cinnoline; imidazoline; 1,3,5-triazine; thiazole; pteridine; indazole; amines; polyamines; amides; polyamides; and 2-ethyl-4-methyl imidazole; and combinations thereof. The chosen hardening agent often effects the range of temperatures over which a hardenable resin is able to cure. By way of example, and not of limitation, in subterranean formations having a temperature of about 60° F. to about 250° F., amines and cyclo-aliphatic amines such as piperidine, triethylamine, tris(dimethylaminomethyl)phenol, and dimethylaminomethyl)phenol may be preferred. In subterranean formations having higher temperatures, 4,4′-diaminodiphenyl sulfone may be a suitable hardening agent. Hardening agents that comprise piperazine or a derivative of piperazine have been shown capable of curing various hardenable resins from temperatures as low as about 50° F. to as high as about 350° F.

The hardening agent used may be included in the liquid hardening agent component in an amount sufficient to at least partially harden the resin composition. In some embodiments of the present invention, the hardening agent used is included in the liquid hardening agent component in the range of about 0.1% to about 95% by weight of the liquid hardening agent component. In other embodiments, the hardening agent used may be included in the liquid hardening agent component in an amount of about 15% to about 85% by weight of the liquid hardening agent component. In other embodiments, the hardening agent used may be included in the liquid hardening agent component in an amount of about 15% to about 55% by weight of the liquid hardening agent component.

In some embodiments, the consolidating agent may comprise a liquid hardenable resin component emulsified in a liquid hardening agent component, wherein the liquid hardenable resin component is the internal phase of the emulsion and the liquid hardening agent component is the external phase of the emulsion. In other embodiments, the liquid hardenable resin component may be emulsified in water and the liquid hardening agent component may be present in the water. In other embodiments, the liquid hardenable resin component may be emulsified in water and the liquid hardening agent component may be provided separately. Similarly, in other embodiments, both the liquid hardenable resin component and the liquid hardening agent component may both be emulsified in water.

The optional silane coupling agent may be used, among other things, to act as a mediator to help bond the resin to formation particulates or proppant particulates. Examples of suitable silane coupling agents include, but are not limited to, N-2-(aminoethyl)-3-aminopropyltrimethoxysilane, and 3-glycidoxypropyltrimethoxysilane, and combinations thereof. The silane coupling agent may be included in the resin component or the liquid hardening agent component (according to the chemistry of the particular group as determined by one skilled in the art with the benefit of this disclosure). In some embodiments of the present invention, the silane coupling agent used is included in the liquid hardening agent component in the range of about 0.1% to about 3% by weight of the liquid hardening agent component.

Any surfactant compatible with the hardening agent and capable of facilitating the coating of the resin onto particulates in the subterranean formation may be used in the liquid hardening agent component. Such surfactants include, but are not limited to, an alkyl phosphonate surfactant (e.g., a C12 to C22 alkyl phosphonate surfactant), an ethoxylated nonyl phenol phosphate ester, one or more cationic surfactants, and one or more nonionic surfactants. Combinations of one or more cationic and nonionic surfactants also may be suitable. Examples of such surfactant combinations are described in U.S. Pat. No. 6,311,773 entitled “Resin Composition and Methods of Consolidating Particulate Solids in Wells With or Without Closure Pressure” filed on Jan. 28, 2000, the relevant disclosure of which is incorporated herein by reference. The surfactant or surfactants that may be used are included in the liquid hardening agent component in an amount in the range of about 1% to about 10% by weight of the liquid hardening agent component.

While not required, examples of hydrolyzable esters that may be used in the liquid hardening agent component include, but are not limited to, a combination of dimethylglutarate, dimethyladipate, dimethylsuccinate; dimethylthiolate; methyl salicylate; dimethyl salicylate; and dimethylsuccinate; and combinations thereof. When used, a hydrolyzable ester is included in the liquid hardening agent component in an amount in the range of about 0.1% to about 3% by weight of the liquid hardening agent component. In some embodiments a hydrolyzable ester is included in the liquid hardening agent component in an amount in the range of about 1% to about 2.5% by weight of the liquid hardening agent component.

Use of a diluent or liquid carrier fluid in the liquid hardening agent component is optional and may be used to reduce the viscosity of the liquid hardening agent component for ease of handling, mixing, and transferring. As previously stated, it may be desirable in some embodiments to not use such a solvent for environmental or safety reasons. Any suitable carrier fluid that is compatible with the liquid hardening agent component and achieves the desired viscosity effects is suitable for use in the present invention. Some suitable liquid carrier fluids are those having high flash points (e.g., about 125° F.) because of, among other things, environmental and safety concerns; such solvents include, but are not limited to, butyl lactate, dipropylene glycol methyl ether, dipropylene glycol dimethyl ether, dimethyl formamide, diethyleneglycol methyl ether, ethyleneglycol butyl ether, diethyleneglycol butyl ether, propylene carbonate, methanol, butyl alcohol, d′ limonene, fatty acid methyl esters, and combinations thereof. Other suitable liquid carrier fluids include aqueous dissolvable solvents such as, for example, methanol, isopropanol, butanol, glycol ether solvents, and combinations thereof. Suitable glycol ether liquid carrier fluids include, but are not limited to, diethylene glycol methyl ether, dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a C2 to C6 dihydric alkanol having at least one C1 to C6 alkyl group, mono ethers of dihydric alkanols, methoxypropanol, butoxyethanol, hexoxyethanol, and isomers thereof. Combinations of these may be suitable as well. Selection of an appropriate liquid carrier fluid is dependent on, inter alia, the resin composition chosen.

Other resins suitable for use in the present invention are furan-based resins. Suitable furan-based resins include, but are not limited to, furfuryl alcohol resins, furfural resins, combinations of furfuryl alcohol resins and aldehydes, and a combination of furan resins and phenolic resins. Of these, furfuryl alcohol resins may be preferred. A furan-based resin may be combined with a solvent to control viscosity if desired. Suitable solvents for use in the furan-based consolidation fluids of the present invention include, but are not limited to, 2-butoxy ethanol, butyl lactate, butyl acetate, tetrahydrofurfuryl methacrylate, tetrahydrofurfuryl acrylate, esters of oxalic, maleic and succinic acids, and furfuryl acetate. Of these, 2-butoxy ethanol is preferred. In some embodiments, the furan-based resins suitable for use in the present invention may be capable of enduring temperatures well in excess of 350° F. without degrading. In some embodiments, the furan-based resins suitable for use in the present invention are capable of enduring temperatures up to about 700° F. without degrading.

Optionally, the furan-based resins suitable for use in the present invention may further comprise a curing agent to facilitate or accelerate curing of the furan-based resin at lower temperatures. The presence of a curing agent may be particularly useful in embodiments where the furan-based resin may be placed within subterranean formations having temperatures below about 350° F. Examples of suitable curing agents include, but are not limited to, organic or inorganic acids, such as, inter alia, maleic acid, fumaric acid, sodium bisulfate, hydrochloric acid, hydrofluoric acid, acetic acid, formic acid, phosphoric acid, sulfonic acid, alkyl benzene sulfonic acids such as toluene sulfonic acid and dodecyl benzene sulfonic acid (“DDBSA”), and combinations thereof. In those embodiments where a curing agent is not used, the furan-based resin may cure autocatalytically.

Still other resins suitable for use in the methods of the present invention are phenolic-based resins. Suitable phenolic-based resins include, but are not limited to, terpolymers of phenol, phenolic formaldehyde resins, and a combination of phenolic and furan resins. In some embodiments, a combination of phenolic and furan resins may be preferred. A phenolic-based resin may be combined with a solvent to control viscosity if desired. Suitable solvents for use in the present invention include, but are not limited to butyl acetate, butyl lactate, furfuryl acetate, and 2-butoxy ethanol. Of these, 2-butoxy ethanol may be preferred in some embodiments.

Yet another resin-type material suitable for use in the methods of the present invention is a phenol/phenol formaldehyde/furfuryl alcohol resin comprising of about 5% to about 30% phenol, of about 40% to about 70% phenol formaldehyde, of about 10% to about 40% furfuryl alcohol, of about 0.1% to about 3% of a silane coupling agent, and of about 1% to about 15% of a surfactant. In the phenol/phenol formaldehyde/furfuryl alcohol resins suitable for use in the methods of the present invention, suitable silane coupling agents include, but are not limited to, N-2-(aminoethyl)-3-aminopropyltrimethoxysilane, and 3-glycidoxypropyltrimethoxysilane. Suitable surfactants include, but are not limited to, an ethoxylated nonyl phenol phosphate ester, combinations of one or more cationic surfactants, and one or more nonionic surfactants and an alkyl phosphonate surfactant.

In some embodiments, resins suitable for use in the consolidating agent emulsion compositions of the present invention may optionally comprise filler particles. Suitable filler particles may include any particle that-does not adversely react with the other components used in accordance with this invention or with the subterranean formation. Examples of suitable filler particles include silica, glass, clay, alumina, fumed silica, carbon black, graphite, mica, meta-silicate, calcium silicate, calcine, kaoline, talc, zirconia, titanium dioxide, fly ash, and boron, and combinations thereof. In some embodiments, the filler particles may range in size of about 0.01 μm to about 100 μm. As will be understood by one skilled in the art, particles of smaller average size may be particularly useful in situations where it is desirable to obtain high proppant pack permeability (i.e., conductivity), and/or high consolidation strength. In certain embodiments, the filler particles may be included in the resin composition in an amount of about 0.1% to about 70% by weight of the resin composition. In other embodiments, the filler particles may be included in the resin composition in an amount of about 0.5% to about 40% by weight of the resin composition. In some embodiments, the filler particles may be included in the resin composition in an amount of about 1% to about 10% by weight of the resin composition. Some examples of suitable resin compositions comprising filler particles are described in U.S. Patent Publication No. 2008/0006405 entitled “Methods and Compositions for Enhancing Proppant Pack Conductivity and Strength” filed on Jul. 6, 2006, the entire disclosure of which is herein incorporated by reference.

Silyl-modified polyamide compounds may be described as substantially self-hardening compositions that are capable of at least partially adhering to particulates in the unhardened state, and that are further capable of self-hardening themselves to a substantially non-tacky state to which individual particulates such as formation fines will not adhere to, for example, in formation or proppant pack pore throats. Such silyl-modified polyamides may be based, for example, on the reaction product of a silating compound with a polyamide or a combination of polyamides. The polyamide or combination of polyamides may be one or more polyamide intermediate compounds obtained, for example, from the reaction of a polyacid (e.g., diacid or higher) with a polyamine (e.g., diamine or higher) to form a polyamide polymer with the elimination of water. Other suitable silyl-modified polyamides and methods of making such compounds are described in U.S. Pat. No. 6,439,309 entitled “Compositions and Methods for Controlling Particulate Movement in Wellbores and Subterranean Formations” filed on Dec. 13, 2000, the relevant disclosure of which is herein incorporated by reference.

To facilitate a better understanding of the present invention, the following examples of preferred embodiments are given. In no way should the following examples be read to limit, or to define, the scope of the invention.

EXAMPLES

As illustrated in FIG. 1, a cell was assembled with the following in order from bottom to top: a bottom plunger, an 80-mesh screen, a 40/60-mesh sand, 60 g of 20/40 Brady sand+20 g of Brazos River fines, 16/20 mesh lightweight ceramic proppant (CarboLite® available from Carbo Ceramics), a 40-mesh screen, and a top plunger. In the following tests, samples were generally injected into the cell via the top plunger, allowed to consolidate, then flushed from the reverse direction (i.e., from the bottom plunger) such that the effluent was collected and analyzed for the concentration of solids so as to indicate the efficacy of consolidation. Further, in the following test, the cell was maintained at 200° F. with heat tape wrapped around the exterior of the cell.

In Test 1, 100 mL of 3% CLA-WEB® solution (a water-soluble cationic oligomer, available from Halliburton Energy Services, Inc.) was passed through to the cell via the top plunger at 8 mL per minute, followed by 100 mL of PROPSTOP® ABC solution (a consolidating agent, available from Halliburton Energy Services, Inc.) (prepared by diluting 5 mL of PROPSTOP® ABC in 95 mL of 3% KCl brine). No post-flush was performed. The cell was then shut-in for 20 hours at 200° F. Then in the reverse flow direction, i.e., from the bottom plunger, a solution of 3% CLA-WEB® was flowed and collected in 100 mL increments at flow rates of 50, 100, 150, 200, and 300 mL/min. After the reverse flow procedure, the packed cell was allowed to cool and the Brazos River sand fines were removed for visual inspection. As shown in FIG. 2, after removal, the Brazos River sand fines stay in the cylindrical shape of the cell with only a small percentage of the fines on the outer surface sloughing off during handling, indicating significant cohesion and consolidation between particulate grains of sand and fines.

In Test 2, 100 mL of 3% CLA-WEB® solution (a water-soluble cationic oligomer, available from Halliburton Energy Services, Inc.) was passed through to the cell via the top plunger at 8 mL per minute, followed by 100 mL of PROPSTOP® ABC solution (a consolidating agent, available from Halliburton Energy Services, Inc.) (prepared by diluting 5 mL of PROPSTOP® ABC in 95 mL of 3% KCl brine). No post-flush was performed. The cell was then shut-in for 96 hours at 200° F. Then in the reverse flow direction, i.e., from the bottom plunger, a solution of 3% CLA-WEB® was flowed and collected in 100 mL increments at flow rates of 50, 100, 150, 200, and 300 mL/min. After the reverse flow procedure, the packed cell was allowed to cool and the Brazos River sand fines were removed for visual inspection. As shown in FIG. 3, after removal, the Brazos River sand fines stay in the cylindrical shape of the cell with only a small percentage of the fines on the outer surface sloughing off during handling, indicating significant cohesion and consolidation between particulate grains of sand and fines.

Test 3 was a control test; i.e., without treatment of the ultra-low concentration resin treatment. In Test 3, 100 mL of 3% CLA-WEB® solution (a water-soluble cationic oligomer, available from Halliburton Energy Services, Inc.) was passed through to the cell via the top plunger at 8 mL per minute. No post-flush was performed. Then in the reverse flow direction, i.e., from the bottom plunger, a solution of 3% CLA-WEB® was flowed and collected in 100 mL increments at flow rates of 50, 100, 150, 200, and 300 mL/min. After the reverse flow procedure, the packed cell was allowed to cool and the Brazos River sand fines were removed. During removal, the Brazos River sand fines fell apart by gravity after the bottom plunger was removed indicating there was no attainable cohesion or consolidation between particulate grains of sand and fines. Visual inspection of the proppant portion showed that the pore spaces were filled and saturated with Brazos River sand fines.

The total suspended solids concentration in the various effluent samples was determined by EPA method SM 2540-D, results shown in Table 1 below. Further, visual inspection of the Brazos River sand fines for Tests 1 and 2, FIGS. 2-3, show the ultra-low concentration resin treatment consolidates the Brazos River sand fines.

TABLE 1 Effluent Total Suspended Solids Concentration (mg/L) Flow Rate Test 1 Test 2 Test 3 (control)  50 mL/min 31.66 26.01 40 100 mL/min 39.80 23.41 6,443 150 mL/min 71.36 27.00 11,486 200 mL/min 104.06 22.66 6,979 300 mL/min 385.32 25.05 4,702

This example demonstrates that curable resins at lower concentrations including those described herein advantageously provide stronger cohesion between formation fines so as to reduce the flow back of formation fines during the production of hydrocarbons from subterranean formations.

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present invention. The invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined hereinto mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted. 

The invention claimed is:
 1. A method comprising: providing a consolidating treatment fluid that comprises an aqueous base fluid and a water-based curable resin at about 0.01% to about 3% by weight of the aqueous base fluid; introducing the consolidating treatment fluid into at least a portion of a subterranean formation comprising unconsolidated formation fines; and allowing the resin to cure so as to consolidate the unconsolidated formation fines.
 2. The method of claim 1, wherein the water-based curable resin comprises at least one selected from the group consisting of an epoxy-based resin, a novolak resin, a polyepoxide resin, a phenol-aldehyde resin, a urea-aldehyde resin, a urethane resin, a phenolic resin, a furan resin, a furan/furfuryl alcohol resin, a phenolic/latex resin, a phenol formaldehyde resin, a polyester resin and hybrids and copolymers thereof, a polyurethane resin and hybrids and copolymers thereof, an acrylate resin, and any combination thereof.
 3. The method of claim 1, wherein the water-based curable resin comprises a two-component epoxy-based resin at about 0.01% to about 3% by weight of the aqueous base fluid, an amine-based curing agent at about 0.01% to about 3% by weight of the aqueous base fluid, and a silane coupling agent at about 0.01% to about 2% by weight of the aqueous base fluid.
 4. The method of claim 1, wherein the consolidating treatment fluid is foamed.
 5. The method of claim 1, wherein the consolidating treatment fluid further comprises a clay stabilizing agent.
 6. The method of claim 1, wherein the consolidating treatment fluid further comprises at least one additive selected from the group consisting of a salt, a weighting agent, an inert solid, a fluid loss control agent, an emulsifier, a dispersion aid, a corrosion inhibitor, an emulsion thinner, an emulsion thickener, a viscosifying agent, a gelling agent, a surfactant, a particulate, a proppant, a gravel particulate, a lost circulation material, a pH control additive, a breaker, a biocide, a crosslinker, a stabilizer, a chelating agent, a scale inhibitor, a gas hydrate inhibitor, a mutual solvent, an oxidizer, a reducer, a friction reducer, a clay stabilizing agent, or any combination thereof.
 7. The method of claim 1, wherein introducing the consolidating treatment fluid is at matrix flow rate.
 8. The method of claim 1 further comprising: introducing a preflush treatment fluid prior to introduction of the consolidating treatment fluid, wherein the preflush treatment fluid comprises a second aqueous base fluid.
 9. The method of claim 1 further comprising: producing hydrocarbons is from a production wellbore; and wherein introducing the consolidating treatment fluid is through an injection wellbore.
 10. A method comprising, in order: introducing a preflush treatment fluid into at least a portion of a subterranean formation comprising unconsolidated formation fines, the preflush treatment fluid comprising a first aqueous base fluid; introducing a consolidating treatment fluid in the portion of the subterranean formation, the treatment fluid comprising a second aqueous base fluid and a water-based curable resin at about 0.01% to about 3% by weight of the second aqueous base fluid; allowing the resin to cure so as to consolidate the unconsolidated formation fines; and producing hydrocarbon fluids from the portion of the subterranean formation.
 11. The method of claim 10, wherein the water-based curable resin comprises at least one selected from the group consisting of an epoxy-based resin, a novolak resin, a polyepoxide resin, a phenol-aldehyde resin, a urea-aldehyde resin, a urethane resin, a phenolic resin, a furan resin, a furan/furfuryl alcohol resin, a phenolic/latex resin, a phenol formaldehyde resin, a polyester resin and hybrids and copolymers thereof, a polyurethane resin and hybrids and copolymers thereof, an acrylate resin, and any combination thereof.
 12. The method of claim 10, wherein the water-based curable resin comprises a two-component epoxy-based resin at about 0.01% to about 3% by weight of the second aqueous base fluid, an amine-based curing agent at about 0.01% to about 3% by weight of the second aqueous base fluid, and a silane coupling agent at about 0.01% to about 2% by weight of the second aqueous base fluid.
 13. The method of claim 10, wherein the consolidating treatment fluid is foamed.
 14. The method of claim 10, wherein the consolidating treatment fluid further comprises a clay stabilizing agent.
 15. The method of claim 10, wherein introducing the consolidating treatment fluid is at matrix flow rate.
 16. A method comprising, in order: introducing a consolidating treatment fluid in the portion of the subterranean formation, the treatment fluid comprising an aqueous base fluid, a two-component epoxy-based resin at about 0.01% to about 3% by weight of the aqueous base fluid, an amine-based curing agent at about 0.01% to about 3% by weight of the aqueous base fluid, and a silane coupling agent at about 0.01% to about 2% by weight of the aqueous base fluid; allowing the resin to cure so as to consolidate the unconsolidated formation fines; and producing hydrocarbon fluids from the portion of the subterranean formation.
 17. The method of claim 16, wherein the consolidating treatment fluid is foamed.
 18. The method of claim 16, wherein the consolidating treatment fluid further comprises a clay stabilizing agent.
 19. The method of claim 16, wherein introducing the consolidating treatment fluid is at matrix flow rate.
 20. The method of claim 16, wherein introducing the consolidating treatment fluid is through an injection wellbore and producing hydrocarbons is from a production wellbore. 